It has long been known that only a portion of the oil can be recovered from an oil-bearing subterranean formation as a result of the natural energy of the reservoir. So-called secondary recovery techniques are used to force more oil out of the reservoir, the simplest method of which is by direct replacement with another medium, usually water or gas.
Water-flooding is one of the most successful and extensively used secondary recovery methods. Water is injected, under pressure, into reservoir rocks via injection wells, driving the oil through the rock towards production wells. The water used in water-flooding is generally saline water from a natural source such as seawater.
According to U.S. Pat. No. 5,855,243, oil recovery is usually inefficient in subterranean formations where the mobility of the in situ oil being recovered is significantly less than that of the drive fluid used to displace the oil. Mobility of a fluid phase in a formation is defined by the ratio of the fluid's relative permeability to its viscosity. For example, when waterflooding is applied to displace very viscous heavy oil from a formation, the process is very inefficient because the oil mobility is much less than the water mobility. The water quickly channels though the formation to the producing well, bypassing most of the oil and leaving it unrecovered. It is said that water-in-oil macroemulsions have been proposed as a method for producing viscous drive fluids that can maintain effective mobility control while displacing moderately viscous oils. For example, the use of water-in-oil and oil-in-water macroemulsions have been evaluated as drive fluid to improve oil recovery of viscous oils. Such emulsions have been created by addition of sodium hydroxide to acidic crude oil from Canada and Venezuela. In this study, the emulsions were stabilized by soap films created by saponification of acidic hydrocarbon components in the crude oil by sodium hydroxide These soap films reduced the oil/water interfacial tension, acting as surfactants to stabilize the water-in-oil emulsion. It is well known, therefore that the stability of such emulsions substantially depends on the use of sodium hydroxide (i.e., caustic) for producing a soap film to reduce the oil/water interfacial tension.
U.S. Pat. No. 5,855,243 teaches that practical applications of the use of caustic for producing emulsions has been limited by the high costs of the caustic, likely adsorption of the soap films onto the formation rock leading to gradual breakdown of the emulsion, and the sensitivity of the emulsion viscosity to minor changes in water salinity and water content. For example because most formations contain water with many dissolved solids, emulsions requiring fresh or distilled water often fail to achieve design potential because such low-salinity conditions are difficult to achieve and maintain within the actual formation. Ionic species can be dissolved from the rock and the injected fresh water can mix with the high-salinity resident water, causing breakdown of the low-tension stabilized emulsion.
According to the invention of U.S. Pat. No. 5,855,243, there is provided a method for producing a fluid having hydrocarbons from a subterranean formation having hydrocarbons and formation solids, comprising:                (a) making a solids-stabilized emulsion having water, oil and undissolved solids, said solids comprising particles selected from the group consisting of formation solid particles, non-formation solid particles, and combinations thereof;        (b) contacting the formation with said emulsion; and        (c) producing said fluid from the formation using said emulsion.        
U.S. Pat. No. 5,855,243 is primarily focused on injecting a pre-formed solids stabilized emulsion into a subterranean formation. However, a problem with injecting a pre-formed emulsion into a formation is that the emulsion will have low injectivity compared with an injection water owing to the emulsion having a higher viscosity than water, and the emulsion containing droplets that cause formation face blockage. In addition, filtration of the emulsion droplets reduces the permeability of the near-wellbore region of the injection well. In order to maintain the same injection rate for an emulsion as for water, a higher injection pressure will be required which may not be possible because of pump constraints or formation fracturing concerns. Alternative solutions to the lower injectivity of emulsions include providing more injection wells or deliberately fracturing the injection wells to improve injectivity. However, additional injection wells result in increased capital expenditure while deliberately fracturing the injection wells increases costs and raises the issue of fracture control.
Although U.S. Pat. No. 5,855,243 also teaches that solids-stabilized emulsions can be generated “in situ” by injecting the requisite solid particles dispersed in water into a formation having hydrocarbons which can be used for making the emulsion in situ, no examples of oil recovery using emulsions formed in situ are provided. Instead, the examples are concerned with injecting pre-formed emulsions into a core.
U.S. Pat. No. 5,855,243 teaches that the water used for making the solids-stabilized emulsion should have sufficient ion concentration to keep the emulsion stable under formation conditions. Preferably, formation water (water produced from the formation) is used to make the emulsion. Fresh water could be used provided that the ion concentration is adjusted as needed for stabilizing the emulsion under formation conditions. Contrary to the teachings of U.S. Pat. No. 5,855,243, it has now been found that a stable water-in-oil emulsion may be formed in situ when: (a) the oil that is contained in the formation has an American Petroleum Institute (API) gravity of less than 30° and a viscosity under reservoir conditions of greater than 1 centipoise; (b) both the injected water and the oil that is present in the pores of the formation have undissolved solids suspended therein; and (c) the ratio of the total multivalent cation content of the injection water to the total multivalent cation content of the connate water is less than 0.9, preferably, less than 0.8.